US8591861B2

US8591861B2 - Hydrogenating pre-reformer in synthesis gas production processes

Info

Publication number: US8591861B2
Application number: US12/061,355
Authority: US
Inventors: Franklin D. LOMAX; Rama A. Zakaria; Maxim Lyubovsky; Stephen C. Leviness
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2007-04-18
Filing date: 2008-04-02
Publication date: 2013-11-26
Also published as: WO2009102383A1; US20080260631A1; US20080262110A1

Abstract

A production process includes combining a first feed stream and a second feed stream to produce, in a pre-reforming reactor, a first product stream comprising CH₄and H₂O; wherein the first feed stream contains a mixture of H₂and at least one selected from the group consisting of hydrocarbons having two or more carbon atoms and alcohols having two or more carbon atoms, and the mixture has a hydrogen stoichiometric ratio (λ) of at least 0.1, and the second feed stream contains steam; feeding the first product stream into a reforming reactor; and reacting the first product stream in the reforming reactor to produce a second product stream containing CO and H₂; and a catalyst for use in the process. Conversion of the second product stream to synthetic crude, methanol, higher alcohols, and/or DME may also be undertaken. Yet further conversion of a synthetic crude to lubricants, diesel and the like, and/or the alcohols/DME to gasoline, olefins, and/or other oxygenates may also be included.

Description

This application is a continuation-in-part of co-pending U.S. application Ser. No. 12/029,826, filed on Feb. 12, 2008, which claimed the benefit of U.S. Provisional Application Ser. No. 60/912,495, filed on Apr. 16, 2007, the disclosures of which are incorporated herein in their entirety.

BACKGROUND OF THE INVENTION

Embodiments of the invention relate to processes for producing synthesis gas (“syngas”), a mixture primarily comprised of CO and H2. In particular, embodiments of the invention relate to processes for producing synthesis gas through steam reforming. Hydrogen production, as a component of synthesis gas production, is typically performed through catalytic steam reforming. The general reaction for catalytic steam reforming is as follows:

C_{x} H_{y} O_{z} + (x - z) H_{2} O \overset{catalyst}{\to} x CO + (x - z + \frac{y}{2}) H_{2}

Synthesis gas (including hydrogen) can be produced from methane containing feedstocks by steam methane reforming (SMR), an endothermic reaction carried out either in heat exchange reactors, or by other means where substantial heat may be transferred to the reacting fluid, such as in the case of autothermal reforming (ATR), where a portion of the feedstock is combusted inside the reactor to provide heat for steam reforming either subsequently or in the same location as the combustion. Synthesis gas can also be produced from methane containing feedstocks by CO2 (“dry”) reforming, catalytic or thermal partial oxidation (CPOx or POx, respectively) and other processes known in the art. If hydrocarbon or alcohol feedstocks enriched, either naturally or by purposeful addition, in compounds with two or more carbon atoms per molecule (C2+ hydrocarbons) are used for hydrogen, or synthesis gas, generation, the risk of catalyst deactivation by carbon deposition in the hydrogen or synthesis gas generation reactor is greatly increased. As used herein, “enriched in compounds with two or more carbon atoms per molecule” generally means having greater than 5% C2+ hydrocarbons.

In order to minimize the risk of carbon deposition, existing hydrogen and synthesis gas production processes typically employ at least one adiabatic catalytic reactor prior to the synthesis gas generation reactor. These adiabatic reactors are referred to as pre-reformers.

In existing hydrogen and synthesis gas production processes employing pre-reformers and steam methane reformers, the hydrocarbon feedstock is mixed with 1 to 5% hydrogen by volume, then is subjected to a hydrodesulphurization (HDS) pre-treatment step to remove sulphur. The feedstock hydrocarbons are then mixed with superheated steam in a ratio determined by the average molecular weight of the feedstock molecules. Natural gas or other feedstocks where the average carbon number is less than two are processed with a molar steam to carbon ratio between 3:1 and 5:1. Higher molecular weight feedstocks are often processed with steam to carbon ratios as much as twice as high, between about 6:1 and 10:1. These high steam flowrates are used to suppress carbon formation, and enhance the steam reforming reaction. High steam to carbon ratios disadvantageously increase energy usage in the synthesis gas and/or hydrogen production process.

Existing hydrogen and synthesis gas production processes employing air, oxygen-enriched air, or pure oxygen feedstocks also typically mix the hydrocarbon feedstock with 1 to 5% hydrogen by volume and then conduct hydrodesulphurization to remove sulphur. Steam addition rates, expressed as a molar steam to carbon ratio, in these processes, especially when targeting production of synthesis gas with H2/CO ratios in the 2.0-2.5 range, are much lower than those employed in steam methane reforming, typically in the range of 0.5-1.0, although processes employing ratios as low as 0.2-0.4 (and lower) are known.

Because the reaction rates for steam reforming are low at the pre-reforming feed temperatures of 400° C. to 500° C., pre-reforming catalysts are prepared with very high metal loadings, above 10% by weight, and high metal surface areas. These high metal surface areas present several challenges. First, they are subject to rapid sintering and reduction of activity if feedstock temperature is not controlled very closely. Second, they present substantial safety risk due to their pyrophoric reaction with oxygen, especially when nickel metal is used, thus necessitating great care in handling the catalysts during reduction and subsequent operation. Further, even at the elevated steam to carbon ratios employed in existing steam methane reformer based hydrogen or synthesis gas production processes using pre-reformers for C2+ feedstocks, deactivation by carbon deposition remains a problem. At the much lower steam to carbon ratios typically employed in autothermal reforming or catalytic partial oxidation, deactivation by carbon deposition is especially problematic. Typically, volatile alkali or alkali-silicate promoters are added to suppress carbon deposition. Such promoters are very effective, but disadvantageously reduce catalyst reaction rate, necessitating larger pre-reforming reactors. Further, the promoters tend to volatilize and subsequently deposit on downstream catalysts and equipment. This causes deactivation of downstream catalysts and potential corrosion damage to equipment, both of which may lead to serious operation problems such as hot banding of reformer tubes, carbon deposition and eventual tube failure. Further, the protective effects of the alkali promoters are lost after they are volatilized, such that eventual pre-reformer catalyst failure is assured in such existing pre-reformers. Upon failure, the highly-reactive catalyst must be safely removed from the pre-reformer reactor and replaced.

There is a need for an improved hydrogen and synthesis gas production method that can process feedstocks containing 20% or more of molecules having at least two carbon atoms each without being deactivated by carbon deposition and without requiring the addition of excessive amounts of steam (S/C ratios of 6 to 10:1, or higher).

SUMMARY OF THE INVENTION

An embodiment of the invention provides a process having the steps of a) combining a first feed stream and a second feed stream to produce, in a pre-reforming reactor, a first product stream comprising CH₄and H₂O; and b) feeding the first product stream into a syngas generation reactor; and reacting the first product stream in the syngas generation reactor to produce a second product stream comprising synthesis gas. In some embodiments, the first feed stream is a mixture of H₂and at least one component selected from hydrocarbons having two or more carbon atoms or alcohols having two or more carbon atoms with the mixture having a hydrogen stoichiometric ratio (λ) of at least 0.1. In some embodiments, the second feed stream is steam. In some embodiments, the hydrogen stoichiometric ratio (λ) is 0.1≦λ≦1.5. In some embodiments, the hydrogen stoichiometric ratio (λ) is 0.25≦λ≦1. The syngas generation reactor may be a steam methane reformer, a CO₂dry reformer, an autothermal reformer, a catalytic partial oxidation reactor or a thermal partial oxidation reactor. In some embodiments, the syngas generation reactor may be an ion transport membranes or a microchannel reactor. In some embodiments, the second product stream is produced using air, oxyen-enriched air, or nominally 100% oxygen.

In some embodiments, the process also includes c) adding a low C₂₊ hydrocarbon gas to the first product stream prior to feeding the first product stream into the reforming reactor. In some embodiments, the low C₂₊ gas is natural gas, wellhead gas, coal bed methane (“CBM”), gas obtained from coal gasification, gas obtained from biomass gasification or a combination thereof.

In some embodiments, the process further includes producing synthetic crude from the second product stream. In some embodiments, the process further includes producing one or more products selected from the group of lubricant basestock, middle distillate fuels, diesel, lubricants, gasoline, jet fuel, and linear alkylbenzene from the synthetic crude. In some embodiments, all or a portion of the H₂in the first feed stream is obtained by chemical and/or physical separation of H₂from a portion of the second product stream. In some embodiments, the step of producing the synthetic crude occurs in a Fischer-Tropsch reactor utilizing a Co- or Ru- or Fe-based Fischer-Tropsch catalyst; the Fischer-Tropsch reactor produces a tail gas; and all or a portion of the H₂in the first feed stream is obtained by chemical and/or physical separation of H₂from the tail gas.

In some embodiments, the process further includes producing an oxygenate from the second product stream. In some embodiments, the oxygenate may be methanol, ethanol, dimethyl ether and combinations thereof. In some embodiments, the process further includes producing one or more products selected from the group of olefins, diesel and gasoline from the oxygenate. In some embodiments, the step of producing the oxygenate occurs in an oxygenate reactor utilizing a Co- or Cu-based oxygenate catalyst; the oxygenate reactor produces a tail gas; and the tail gas is recycled as all or a portion of the first feed stream. In some embodiments, H₂is obtained by chemical and/or physical separation of H₂from the tail gas and added to the first feed stream.

In some embodiments, the process includes desulphurizing the first feed stream prior to feeding the first feed stream into the pre-reforming reactor. In some embodiments, the process includes feeding into the syngas generation reactor with the first product stream an additional feed stream comprising one or more members selected from the group consisting of steam, air, non-air oxidants, mixtures of desulphurized gases selected from hydrocarbons, carbon oxides, and inert gases. In some embodiments, in the pre-reforming reactor, reaction is conducted using a catalyst comprising an active metal dispersed on a support, where the active metal comprises at least one metal selected from the group consisting of Pt, Rh, Ru, Ni, Co, Pd, Ir and combinations thereof. In some embodiments, the support is at least one member selected from the group consisting of TiO₂, ZrO₂, alkaline-earth metal hexaaluminates, monoclinic zirconia and alumina. In some embodiments, the active metal is at least one member selected from the group consisting of Ir, Pt and Pd; and the support comprises at least one member selected from the group consisting of monoclinic zirconia and an alkaline-earth metal hexaaluminate. In some embodiments, the syngas generation reactor is a steam methane reformer and the molar ratio of steam to carbon atom contained in the first feed stream, S:C, is less than about 5:1. In other embodiments, S:C is less than about 4:1 or S:C is between about 3:1 to 4:1. In some embodiments, the active metal is at least one member selected from the group consisting of Ir, Pt and Pd; and the support comprises at least one member selected from the group consisting of alumina and an alkaline-earth hexaaluminate; and the catalyst further comprises one or more rare earth oxide promoters. In some embodiments, the catalyst is in a form such as powders, granulates, tablets, extrudates, and washcoats on ceramic or metallic monoliths, or tubular or plate/corregated plate structures.

In some embodiments, the first feed stream is introduced into the pre-reforming reactor prior to the second feed stream being introduced. In other embodiments, the second feed stream is introduced into the pre-reforming reactor prior to the first feed stream being introduced. In still other embodiments, the first feed stream and second feed stream are introduced into the pre-reforming reactor simultaneously. In some embodiments, the first feed stream and second feed stream are combined prior to introduction into the pre-reforming reactor. In some embodiments, the process is utilized at a production location utilizing a mobile catalyst activation and/or regeneration process.

In some embodiments, the first feed stream has more than 5%, more than 10%, or more than 20% hydrocarbons and/or alcohols having two or more carbon atoms.

In some embodiments, the syngas generation unit is modular and transportable. In other embodiments, the second product stream is produced in a unit that is modular and transportable.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of a first embodiment of the inventive process.

FIG. 2 is a schematic diagram of a second embodiment of the inventive process.

FIG. 3 is a propane conversion versus time plot for catalysts according to an embodiment of the invention.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

It is noted that within the context of embodiments of the invention the designations “first feed stream” and “second feed stream” are used to distinguish the two feedstreams, but does not designate their order of addition into the pre-reforming reactor. Hence the “first feed stream” can be introduced into the pre-reforming reactor either before, after or simultaneously with the “second feedstream” or the first and second feedstreams can be combined prior to introduction into the pre-reforming reactor (or “pre-reformer”) as a single combined feed.

The first feed stream comprises a mixture of H₂and predominantly methane, being enriched in C2+ hydrocarbons (or more generally “hydrocarbons”), the mixture having a hydrogen stoichiometric ratio (λ), as defined herein, of at least 0.1. In some embodiments the first feed stream is primarily comprised of methane. The second feed stream comprises steam.

One embodiment of the invention is shown in FIG. 1 illustrating a typical hydrogen and/or synthesis gas production process 1, in which the first feed stream 2 is co-fed to pre-reforming reactor 3 with the second feed stream which comprises steam 4. The product from the pre-reforming reactor 3 is the first product stream 5 and comprises CH₄and H₂O. The first product stream 5 is fed to the reforming reactor 6, with or without the additional feed 7. Additional feed 7 may include further steam injection, air or other non-air oxidant injection, mixtures of desulphurized gases such as hydrocarbons, carbon oxides, or inerts, for instance as is practiced in reforming for the production of synthesis gas. The product from the reforming reactor 6 is the second product stream 8 and comprises synthesis gas, i.e., a mixture comprising CO and H₂. The second product stream 8 exits the reforming reactor 6 and may be further processed as discussed herein.

Optionally, as shown in FIG. 2, the first feed stream 2 can be treated in a desulphurizing process 11. If the first feed stream 2 possesses bound organic sulphur compounds, including but not limited to mercaptans and thiols, then the desulphurizing process 11 usually includes a hydrogenation step, and a hydrogen-containing gas 9 is added to the desulphurizing process 11 to facilitate sulphur removal. The generalized hydrogen and/or synthesis gas production process 1 illustrated in FIG. 2 can be used to describe both known hydrogen and/or synthesis gas production process for C2+ feedstocks and embodiments of the invention. In embodiments of the invention, the first feed stream 2 has a hyrogen stoichiometric ratio, λ of at least 0.1.

The pre-reforming reactor 3 is preferably operated at temperatures from 350° C. to 600° C. inlet temperature both in embodiments of the invention. To minimize sulphur poisoning, the pre-reforming reactor 3 in some embodiments may be operated at temperatures of 400° C. or higher. To minimize coke formation, the pre-reforming reactor may be operated at or below 550° C. in some embodiments. Operating pressures for the pre-reforming reactor 3 may be between atmospheric pressure and 50 MPa. Common industrial processes are operated between essentially atmospheric pressure and 5 MPa. These typical operating conditions are recited in Twigg, supra, and Rostrup-Nielsen, J. R., Catalytic Steam Reforming, Reprint from Catalysis-Science and Technology, Springer-Verlag, 1984, hereby incorporated by reference, among other sources.

In embodiments of the invention, the amount of hydrogen contained in the first feed stream 2 is increased compared to known processes. The proportion of hydrogen employed in the first feed stream 2 can be best described by a “hydrogenation stoichiometric ratio,” or “hydrogen stoichiometry,” λ, for the hydrogenation reaction of a given hydrocarbon to methane. To define λ, it is convenient to represent the average chemical composition of the molecules in a feed mixture containing hydrocarbons and oxygenated species as C_xH_yO_z, where

x = \sum_{i} n_{i} x_{i}

y = \sum_{i} n_{i} y_{i}

z = \sum_{i} n_{i} z_{i}

and

i is the number of molecular species in the mixture;
n_iis the mole fraction of the i-th molecular species in the mixture; and
x_i, y_iand z_iare the mole fractions of C, H and O, respectively, in the i-th molecular species. The hydrogen stoichiometry, λ, is then defined in terms of molar flow rates, F_M(where M indicates the species, e.g., H₂and/or C_xH_yO_z, to the hydrogen and/or synthesis gas production process as follows:

C_{x} H_{y} O_{z} + (2 x - \frac{y}{2} + z) H_{2} \overset{catalyst}{\to} {x CH}_{4} + {z H}_{2} O

λ = \frac{F_{H_{2}}}{F_{C_{x} H_{y} O_{z}} (2 x - \frac{y}{2} + z)}

For typical hydrocarbon feedstocks, molecules containing other atoms such as nitrogen or sulphur may be present, but the concentration of these molecules is not generally high. Known pre-reforming reactors operating with 1% to 5% di-hydrogen by volume as a ratio to the hydrocarbon feed (which has typically been added prior to and for the hydrocarbon feed hydrodesulphurization step discussed earlier), for a nominal 100% (i.e., about 95-100%) propane feed (C₃H₈) would possess a hydrogen stoichiometry, λ, of between 0.005 and 0.026.

In one embodiment of the present invention, the hydrogen stoichiometry, λ, is preferably at least 0.1. In another embodiment of the present invention, λ is greater than or equal to 0.2, and also less than or equal to 1.5. In another embodiment of the present invention, λ is greater than or equal to 0.25, and also less than or equal to 1. The increased amount of hydrogen in embodiments of the present invention, necessary to achieve the correct hydrogen stoichiometry, may be added prior to the desulphurizing process 11 as part of hydrogen-containing gas 9, or it may be added prior to the pre-reforming reactor 3 as stream 10. Further, distributed injection of the hydrogen may be practiced throughout the pre-reforming reactor 3. The relative amounts of hydrogen added at any of these locations does not limit the application of embodiments of the inventive process.

As noted above, when the level of added hydrogen is at low hydrogen stoichimetry (i.e., λ is less than 0.1), as is employed in known processes, the catalyst may be readily deactivated by carbon formation and deposition, especially at the lower steam to carbon feed ratios typically employed for synthesis gas production. At very high hydrogen stoichiometry (i.e., λ is greater than 1.5), the equilibrium for the subsequent steam methane reforming and water gas shift reactions is adversely affected. In a preferred embodiment of the invention, molecular hydrogen (H₂) is added in amounts to provide a hydrogen stoichiometry of 0.1<λ<1.5, resulting in suppression of catalyst deactivation and rapid reaction of C2+ molecules to C1 (methane) product.

Embodiments of the invention promote the hydrogenation reaction. This reaction is exothermic, whereas the steam reforming reaction is endothermic. Thus, embodiments of the inventive process compensate for the usual subsequent drop in temperature, and thus reaction rate, typically observed in known synthesis gas production methods. Furthermore, embodiments of the inventive method can be employed to obtain a temperature increase in the pre-reforming reactor 3. This temperature increase promotes the hydrogenation reaction rate and both the rate and equilibrium limits to the steam reforming reaction. Thus, embodiments of the inventive process increase conversion of C2+ hydrocarbons and alcohols via hydrogenation while also enhancing the rate and extent of conversion possible through the steam reforming reaction in the same reactor.

Embodiments of this invention are particularly beneficial for synthesis gas production processes which typically employ low (less than 1.0) and very low (less than 0.6) steam to carbon ratios for synthesis gas H2/CO ratio control. For operation with natural gas feedstocks enriched in C2+ hydrocarbons, traditional pre-reforming technology often requires pre-reformer operation with steam to carbon ratios significantly higher than those required for the downstream synthesis gas generation process. Existing technology solutions for this situation typically involve: (1) operation of the pre-reformer at significantly lower steam to carbon ratios than required thereby increasing the risk of carbon deposition in the pre-reformer; (2) operation of the synthesis gas production process at significantly higher steam to carbon ratios than desired thereby producing a synthesis gas containing excess H2, which may need to be removed prior to downstream processing, especially for FT synthesis processes; (3) feeding additional/higher concentrations of CO2 to counter the effects of this “extra” steam on the product synthesis gas H2/CO ratio, and/or (4) cooling the pre-reformer effluent to condense and remove the excess steam, followed by reheating the synthesis gas reactor feed stream, which involves the addition of a number of heat exchangers and vessels as well as a significant decrease in process efficiency.

The inventive method is not catalyst specific and can be applied to various pre-reforming catalysts known and normally used in the art.

In a preferred embodiment, the pre-reformer catalyst has an active component supported on a non-reducible oxide support. Suitable active components include, but are not limited to, Pt, Rh, Ru, Ni, Co, Pd, Ir and any combination thereof. Suitable supports include, but are not limited to, TiO₂, ZrO₂, alkaline-earth metal hexaaluminates (preferably barium hexaaluminate), monoclinic zirconia or alumina. The support of the preferred catalyst has a preferred surface area of from 10 to 250 m²/g, preferably from 80 to 180 m²/g.

One preferred catalyst formulation is described in U.S. Patent Application Publication No. US 2005/0232857, the contents of which is incorporated by reference herein in its entirety, and contains as active metal at least one of Ir, Pt and Pd, on a support of monoclinic zirconia or an alkaline-earth metal hexaaluminate.

The oxide support of a preferred catalyst can optionally include one or more surface area stabilizers. Suitable surface area stabilizers include, but are not limited to, REO (La, Ce, Pr, Nd, Sm), Zr, Y, Ti, Sc and combinations thereof. Such stabilizers can be present in the support in an amount from 0 to 30% by weight, preferably from 5 to 20% by weight, based on amount of support.

The preferred catalyst formulations can be provided in any desired physical form. Preferably the supported catalyst is in a form selected from the group consisting of powders, granulates, tablets, extrudates, and washcoats on ceramic or metallic monoliths, or tubular or plate/corregated plate structures.

In a further embodiment of the invention when used in combination with a downstream steam reforming process for hydrogen and/or high H2/CO ratio syngas production, the pre-reforming process is performed with a molar ratio of steam per carbon atom in the first feed stream, S:C, that is less than 5, preferably less than 4, more preferably between 3 and 4. By using the hydrogen stoichiometry of the inventive process, λ≧0.1, the process enables the use of hydrocarbon feedstocks having higher molecular weight (C2+ enriched), with low steam to carbon ratios being useable.

Other preferred embodiments of the invention include additional downstream processing following the hydrogenation pre-reforming using the hydrogen stoichiometry of the inventive process. In some embodiments of the invention, the conversion of the first product stream 5 in reactor 6 may include steam reforming, autothermal reforming, catalytic or thermal partial oxidation and/or combinations thereof to produce synthesis gas. Such synthesis gas production processes are known and disclosed in U.S. Pat. Nos. 7,335,346; 7,332,147; 7,323,497; 7,297,169; 7,262,334; 7,261,751; 7,255,840; 7,250,151; 7,241,401; 7,232,532; 7,214,331; 7,166,268; 7,105,147; 7,094,363; 7,090,826; 7,087,651; 7,087,192; 7,074,347; 7,067,560; 7,056,488; 7,037,485; 7,033,569; 6,984,371; 6,958,310; 6,953,488; 6,793,700; 6,761,838; 6,749,828; 6,730,285; 6,702,960; 6,695,983; 6,693,060; 6,680,006; 6,673,270; 6,669,744; 6,635,191; 6,609,562; 6,607,678; 6,534,551; 6,527,980; 6,525,104; 6,492,290; 6,489,370; 6,488,907; 6,475,409; 6,461,539; 6,458,334; 6,455,597; 6,409,940; 6,402,989; 6,402,988; 6,387,843; 6,376,423; 6,375,916; 6,355,219; 6,340,437; 6,338,833; 6,312,660; 6,312,658; 6,254,807; 6,224,789; 6,214,066; 6,174,460; 6,155,039; 6,153,163; 6,143,203; 6,143,202; 6,114,400; 6,085,512; 6,077,323; 6,048,472; 6,007,742; 5,993,761; 5,989,457; 5,980,840; 5,980,782; 5,980,596; 5,958,364; 5,935,489; 5,931,978; 5,883,138; 5,855,815; 5,753,143; 5,720,901; 5,714,132; 5,658,497; 5,654,491; 5,653,916; 5,653,774; 5,648,582; 5,637,259; 5,591,238; 5,554,351; 5,500,149; 5,431,855; 5,310,506; 5,252,609; 5,149,464; 5,068,057; 4,985,230; 4,861,351; 4,836,831; 4,767,569; 4,681,701; 4,048,250; 3,573,224; 3,429,678; 3,250,601; 2,942,958; 2,772,149; 2,765,222; 2,684,895; 2,683,152; 2,676,156; 2,665,199; 2,662,004; 2,638,452; 2,635,952; 2,632,690; 2,622,089; 2,543,791; 2,541,657; 2,529,630; 2,522,468; and 2,520,925, the disclosures of which are incorporated herein in their entirety by reference. Some methods of producing synthesis gas utilizing autothermal oxidation employ air or oxygen-enriched air. Such methods are disclosed in U.S. Pat. Nos. 5,733,941; 5,861,441; 6,130,259; 6,169,120; 6,172,124; 6,239,184; 6,277,894; and 6,344,491, the disclosures of which are incorporated herein in their entirety by reference. Yet other methods of producing synthesis gas include the use of oxygen/ion transport membranes, such as the processes disclosed in U.S. Pat. Nos. 6,881,394; 6,402,988; 6,695,983; 6,214,055; 6,114,400; 6,077,323; 6,066,307; and 6,048,472, the disclosures of which are incorporated herein in their entirety by reference. If more than one such synthesis gas production process is utilized, the synthesis gas production processes may be operated serially to or in parallel with each other.

In some embodiments of the invention the product 8 of reforming reactor 6 is further processed to produce a mixture primarily comprised of liquid hydrocarbons, i.e., C5+, or synthetic crude. For example, the synthesis gas product of reactor 6 may be processed in a reactor 13, as shown in FIG. 3. In some embodiments, reactor 13 is a Fischer-Tropsch reactor, as is known in the art. Processes for the production of synthetic crude are known in the art, including for example, in U.S. Pat. Nos. 7,294,253; 7,262,225; 7,241,815; 7,217,741; 7,115,670; 7,109,248; 7,084,180; 7,067,561; 7,067,560; 7,067,559; 7,045,554; 7,045,486; 7,037,947; 7,011,760; 7,001,927; 6,982,287; 6,977,237; 6,942,839; 6,964,398; 6,946,493; 6,872,753; 6,864,293; 6,809,122; 6,797,243; 6,784,212; 6,750,258; 6,730,708; 6,716,887; 6,638,889; 6,558,634; 6,512,018; 6,491,880; 6,479,557; 6,465,530; 6,451,864; 6,403,660; 6,353,035; 6,319,872; 6,344,491; 6,284,807; 6,262,131; 6,235,798; 6,214,890; 6,211,255; 6,180,684; 6,147,126; 6,121,333; 6,103,773; 6,075,061; 6,060,524; 6,043,288; 5,981,608; 5,958,986; 5,905,094; 5,869,541; 5,844,005; 5,817,701; 5,783,607; 5,776,988; 5,770,629; 5,756,419; 5,422,375; 5,348,982; 5,227,407; 5,169,869; 5,135,958; 5,116,879; 5,037,856; 4,978,689; 4,906,671; 4,788,222; 4,686,238; 4,686,313; 4,652,587; 4,640,766; 4,613,624; 4,605,680; 4,605,679; 4,605,676; 4,599,481; 4,594,172; 4,585,798; 4,523,047; 4,492,774; 4,423,265; 4,418,155; 4,399,234; 4,385,193; 4,157,338; 4,088,671; 4,086,262; 4,042,614; 2,957,902; 2,818,418; 2,805,239; and 2,771,481; the disclosures of which are incorporated in their entirety herein by reference.

In yet other embodiments of the invention, additional downstream treatments or product upgrading are utilized to further treat the synthetic crude. As used herein, the term “product upgrading” refers to any subsequent processing or treatment of the synthetic crude to produce an intermediate or end product, including for example, lubricant basestock, lubricants, greases, middle distallate fuels, diesel, linear alkylbenzenes, aviation and jet fuels, gasoline, and other chemicals, i.e., normal- and-iso paraffinic solvents. Such product upgrading methods are disclosed for example in U.S. Pat. Nos. 7,332,072; 7,326,331; 7,320,748; 7,300,565; 7,294,253; 7,288,182; 7,285,206; 7,282,139; 7,282,137; 7,271,304; 7,252,754; 7,238,277; 7,235,172; 7,232,515; 7,198,710; 7,195,706; 7,179,364; 7,156,978; 7,138,047; 7,132,042; 7,125,818; 7,074,320; 7,053,254; 7,033,552; 7,018,525; 6,962,651; 6,939,999; 6,900,366; 6,841,711; 6,833,064; 6,824,574; 6,822,131; 6,797,154; 6,787,022; 6,784,329; 6,768,037; 6,755,961; 6,743,962; 6,727,399; 6,723,889; 6,703,535; 6,702,937; 6,700,027; 6,693,138; 6,686,511; 6,669,743; 6,663,768; 6,635,681; 6,607,568; 6,605,206; 6,602,840; 6,583,186; 6,544,407; 6,515,034; 6,515,032; 6,475,960; 6,458,265; 6,420,618; 6,383,366; 6,375,830; 6,332,974; 6,309,432; 6,296,757; 6,190,532; 6,180,842; 6,179,994; 6,162,956; 6,096,940; 6,025,305; 5,993,644; 5,976,351; 5,888,376; 5,882,505; 5,766,274; 5,750,819; 5,378,348; 5,362,378; 5,246,566; 5,135,638; 4,995,962; 4,975,177; 4,943,672; 4,919,786; 4,520,215; 4,513,156; 4,500,417; 4,385,193; 4,234,412; 4,126,644; 4,071,574; 4,059,648; 4,044,064; 4,041,096; 4,041,095; 3,329,602; 3,268,436; 3,255,101; 3,239,455; 3,224,956; 3,193,490; 3,044,949; 3,001,857; 2,847,358; 2,761,871; 2,752,382; and 2,741,649, the disclosures of which are incorporated by reference herein in their entirety.

In yet other embodiments of the inventive method, the first product stream 5 may be mixed with other hydrocarbon sources prior to or concurrently with introduction into the reforming reactor 6 or other downstream treatments. Such other hydrocarbon sources may include, without limitation, wellhead gas. The term “wellhead gas” as used in the specification and claims refers to any gas at the location of the wellhead (the assembly of fittings, valves, and controls located at the surface and connected to the flow lines, tubing, and casing of the well so as to control the flow from the reservoir), whether it is called “wellhead gas”, “casing head gas”, “residue gas” or the like. The other hydrocarbon source may also include any gas comprising methane and hydrogen, carbon monoxide and/or carbon dioxide, such as gas resulting from, for example, coal gasification and/or biomass gasification processes.

In yet other embodiments of the invention, the second product stream 8 is further processed to produce one or more oxygenates. As used herein, the term oxygenate means any of (1) ethers, including, for example, ethyl tert-butyl ether (ETBE), diisopropyl ether (DIPE), dimethyl ether (DME), methyl tert-butyl ether (MTBE), tert-amyl ethyl ether (TAEE), tert-amyl methyl ether (TAME); and (2) methanol and C₂₊ alcohols, including for example, ethanol (EtOH), propanol, butanol, tert-amyl alcohol (TAA), and tert-butyl alcohol (TBA).

A number of different oxygenate synthesis processes currently known in the art (especially for methanol synthesis), the majority of such processes utilize fixed bed reactors, whether tray, tube-shell, annular, radial, or microchannel. However, three-phase slurry methanol and/or dimethyl ether (DME) synthesis are also known. Known oxygenate synthesis processes are disclosed, for example, in U.S. Pat. Nos. 7,288,689; 7,255,845; 7,144,923; 7,067,558; 7,033,972; 7,015,255; 7,014,835; 6,969,505; 6,894,080; 6,881,759; 6,875,794; 6,800,665; 6,608,114; 6,486,218; 6,433,029; 6,387,963; 6,300,380; 6,255,357; 6,218,439; 6,191,175; 6,069,180; 5,908,963; 5,767,039; 5,753,716; 5,627,295; 5,530,168; 5,512,599; 5,508,246; 5,424,335; 5,287,570; 5,284,878; 5,262,443; 5,219,891; 5,218,003; 5,216,034; 5,179,129; 5,169,869; 5,096,688; 5,063,250; 4,910,227; 4,886,651; 4,876,286; 4,873,267; 4,868,221; 4,812,433; 4,791,141; 4,780,481; 4,766,155; 4,766,154; 4,725,626; 4,666,944; 4,628,066; 4,609,678; 4,540,713; 4,537,909; 4,521,540; 4,521,248; 4,520,216; 4,507,403; 4,481,305; 4,481,012; 4,477,594; 4,476,250; 4,460,378; 4,455,394; 4,444,909; 4,417,000; 4,238,403; 3,950,369; 3,940,428; and 3,939,191.

Additional processing of oxygenates to produce a wide range of products including, for example, olefins, diesel and gasoline, may be undertaken in some embodiments of the invention. Such additional processing of oxygenates are disclosed in U.S. Pat. Nos. 7,199,278; 7,166,757; 7,132,580; 7,078,578; 6,852,897; 6,800,665; 6,768,034; 6,740,783; 6,710,218; 6,632,971; 6,613,951; 6,608,114; 6,534,692; 6,486,219; 6,444,869; 6,399,844; 6,372,949; 6,303,839; 6,191,175; 6,166,282; 6,049,017; 6,045,688; 5,990,369; 5,952,538; 5,750,799; 5,744,680; 5,723,401; 5,714,662; 5,602,289; 5,573,990; 5,545,791; 5,491,273; 5,367,100; 5,316,627; 5,238,898; 5,233,117; 5,191,142; 7,199,278; 7,166,757; 7,132,580; 7,078,578; 6,852,897; 6,800,665; 6,768,034; 6,740,783; 6,710,218; 6,632,971; 6,613,951; 6,608,114; 6,534,692; 6,486,219; 6,444,869; 6,399,844; 6,372,949; 6,303,839; 6,191,175; 6,166,282; 6,121,503; 6,049,017; 6,045,688; 5,990,369; 5,952,538; 5,750,799; 5,744,680; 5,723,401; 5,714,662; 5,602,289; 5,573,990; 5,545,791; 5,491,273; 5,367,100; 5,316,627; 5,238,898; 5,233,117; 5,191,142; 5,191,141; 5,177,279; 5,167,937; 5,130,101; 5,095,163; 5,095,159; 5,047,070; 5,045,287; 5,041,690; 5,028,400; 4,985,203; 4,981,491; 4,935,568; 4,929,780; 4,899,002; 4,898,717; 4,873,390; 4,857,667; 4,849,575; 4,831,195; 4,814,536; 4,814,535; 4,788,377; 4,788,369; 4,788,365; 4,788,042; 4,689,205; 4,684,757; 4,628,135; 4,590,320; 4,579,999; 4,560,807; 4,550,217; 4,513,160; 4,496,786; 4,476,338; 4,449,961; 4,410,751; 4,404,414; 4,393,265; 4,337,336; 4,058,576; 4,052,479; 4,035,430; 4,025,576; 4,025,575; 3,998,898; 3,972,958; and 2,793,241; the disclosures of which are incorporated by reference herein in their entirety.

In yet other embodiments of the invention, the process is conducted at a production location utilizing a mobile catalyst activation and/or regeneration process, such as those processes disclosed in U.S. application Ser. Nos. 12/029,826 and 60/912,495, the disclosures of which are incorporated by reference herein in their entirety. A production location may be located in an industrialized or remote area and may include a natural gas and/or petroleum pumping location, a coal field, and/or a location possessing a biomass source.

In embodiments of the invention, the source of the added hydrogen may be external to the synthesis gas production unit, such as merchant hydrogen procured in high pressure storage cylinders, trailers, or pipeline, as either a liquid or a gas. In other embodiments of the invention the hydrogen could be produced locally external to the synthesis gas production unit. In a preferred embodiment employing the product synthesis gas for downstream methanol synthesis and/or iron catalyzed Fischer-Tropsch synthesis, especially at a remote locations, the methanol and/or FT synthesis tail gas, which typically contains >50% by volume hydrogen, may be added directly to the hydrocarbon feed stream as the hydrogen source. In other preferred embodiments the added hydrogen may be produced from any number of different hydrogen containing streams within the synthesis gas production and/or oxygenate/FT synthesis units through either chemical or physical means. Examples of locations of hydrogen sources and/or methods of hydrogen production from these sources (generally for other purposes) in GTL plants are described in U.S. Pat. Nos. 5,844,005, 6,043,288, 6,103,773, 6,147,126, 6,946,493, 6,958,363, and 7,166,643; the disclosures of which are incorporated by reference herein in their entirety.

EXAMPLES

The following Examples illustrate certain specific embodiments of the disclosed invention and should not be construed as limiting the scope of the invention as many variations are possible within the disclosed invention, as will be recognized by those skilled in the art.

Example 1

Propane was used as hydrocarbon feedstock having three carbon atoms. A pre-reforming reactor having 1.4″ ID was loaded with 10 g of catalyst having 1 wt % Ir deposited on a non-reducible oxide support comprising barium hexaaluminate, making an approximately 1 cm deep catalyst bed. The pre-reforming reaction was conducted under nearly adiabatic conditions. Two ˜2 cm deep layers of 3 mm glass beads were placed below and above the catalyst bed to provide uniform flow of the first and second feedstreams (i.e., reacting gasses) through the bed. Two thermocouples were installed just below and above the catalyst bed to measure the temperature differential across the catalyst.

The pre-reforming reactor was placed in a furnace and the furnace temperature was set constant at 450° C. Propane and steam flows were constant at a molar steam to carbon ratio, or S:C, of 3.7. Hydrogen flow was changed stepwise between hydrogen stoichiometry λ of 1.5, 1.0, 0.5, 0.25 and 0.13. Overall gas space velocity was approximately 35,000 l/hr. The reactor was stabilized for about 1 hour at each step before acquiring a sample of the product, i.e., reformate, gas and switching to the next setting for H₂flow. After the first set of testing the catalyst was aged overnight under the reaction conditions with highest hydrogen gas flow and then the measurements were repeated the next day.

Table 1 shows conversion of C₃H₈into C₁species (CH₄and CO₂, below detectable amounts of CO were observed for all samples) and ΔT between inlet and outlet (T_in-T_out) of the catalyst (negative sign indicates temperature increase over the catalyst). Increasing negative values of ΔT indicate a high degree of the exothermic methanation reaction according to the present invention, whereas high positive values of ΔT indicate endothermic steam reforming reaction dominates the observed conversion of the propane feedstock.

TABLE 1

Hydrogen	C₃H₈
stoichiometry, λ	conversion	ΔT

1.5	95	−56
1	93	−47
0.5	91	−31
0.25	87	−20
0.13	83	−13

After aging overnight

1.5	95	−60
1	93	−48
0.5	91	−34
0.25	87	−22
0.13	83	−14

In all cases, the addition of hydrogen gas according to the inventive method achieves extensive conversion of C2+ hydrocarbons in the feedstock and exhibits exothermic reaction consistent with the desired methanation reaction.

Example 2

The catalyst of Example 1 was aged for about 1500 hrs in a steam methane reforming (SMR) reaction. The catalyst was then removed and loaded into the pre-reforming reactor of Example 1. The same testing procedure was used as described above. Table 2 shows the results for the second catalyst testing.

TABLE 2

Hydrogen	C₃H₈
stoichiometry, λ	conversion	ΔT

1.5	30	−21
1	23	−14
0.5	13	−1
0.25	5	10
0.13	1	12

After aging overnight

1.5	19	−11
1	16	−5
0.5	9	3
0.25	4	9
0.13	1	10

For an aged catalyst, the inventive method yields a surprising increase in C2+ hydrocarbon conversion with increasing hydrogen stoichiometry, λ. Furthermore, the exothermic temperature change increases with increased hydrogen stoichiometry within the inventive range.

Example 3

Ten grams of fresh FCR-69-4 catalyst obtained from Sud-Chemie Corporation was loaded into the pre-reforming reactor of Example 1. The testing procedure of Example 1 was used as described above, with results shown in Table 3. This catalyst has a metal loading of approximately 4 wt % Iridum on an alumina carrier promoted with a mixture of rare earth oxides, namely, CeO₂at 14-20 wt %, La₂O₃at 1-5 wt %, and Y₂O₃at 1-5 wt %, based on amount of catalyst.

TABLE 3

Hydrogenation
stoichiometry	C₃H₈
of feed, λ	conversion	ΔT

1.5	94	N/A
1	92	N/A
0.5	87	N/A
0.25	81	N/A
0.13	76	N/A

After aging overnight

1.5	88	N/A
1	86	N/A
0.5	80	N/A
0.25	73	N/A
0.13	67	N/A

Example 4

Ten grams of fresh FCR-69-1 catalyst obtained from Sud-Chemie Corporation was loaded into the pre-reforming reactor of Example 1. FCR-69-1 has active metal loading of 1 wt % but is otherwise identical to the FCR-69-4 catalyst of the Example 3. The testing procedure of Example 1 was used as described above testing, and the results are shown in Table 4. Even with a reduction in metal loading to ¼ of the value in Example 3, extensive conversion of feed was achieved in proportion to the hydrogen stoichiometry.

TABLE 4

Hydrogen	C₃H₈
stoichiometry, λ	conversion	ΔT

1.5	92	−66
1	81	−59
0.5	58	−34
0.25	20	0
0.13	11	8

After aging overnight

1.5	57	−55
1	54	−49
0.5	32	−17
0.25	14	2
0.13	6	8

FIG. 2 shows the relative conversion C₃H₈versus time for the rare earth oxide promoted catalyst of Example 3 and 4 versus the unpromoted catalyst of Examples 1 and 2. The rare earth oxide promoted catalyst shows a surprising advantage in deactivation rate compared to the unpromoted catalyst. However, the hydrogen stoichiometry λ for the promoted catalysts was uniformly higher than that for the unpromoted catalyst, such that the effects of increased hydrogen stoichiometry and catalyst composition can not be readily separated. In all cases, catalysts provided with hydrogen stoichiometries below the inventive range deactivated within less than two days onstream over multiple tests at different metal loadings and steam to carbon ratios. Both the promoted and unpromoted catalysts possess substantially lower active metal loadings than catalysts used in known pre-reforming reactions. Further, neither catalyst is promoted with alkaline earth promoters with their attendant challenges.

Claims

What is claimed is:

1. A process comprising:

combining a first feed stream and a second feed stream to produce, in a prereforming reactor, a first product stream comprising CH₄and H₂O, wherein:

the first feed stream comprises a mixture of H₂and at least one component selected from the group consisting of hydrocarbons having two or more carbon atoms and alcohols having two or more carbon atoms, wherein more than 5% of the first feed stream comprises said hydrocarbons and/or alcohols having two or more carbon atoms and the amount of hydrogen is such that the first feed stream has a hydrogen stoichiometric ratio (λ) in the range of 0.1≦λ≦1.5; and

the second feed stream comprises steam, wherein the molar ratio of steam to carbon atom contained in the combined first and second feed stream, S:C, is between about 3:1 to 4:1;

so that an exothermic hydrogenation reaction takes place when the first and the second feed streams are combined in the prereforming reactor;

feeding the first product stream into a syngas generation reactor; and

reacting the first product stream in the syngas generation reactor to produce a second product stream comprising synthesis gas.

2. The process of claim 1 further comprising:

adding a low C2+ hydrocarbon gas to the first product stream prior to feeding the first product stream into the syngas generation reactor.

3. The process of claim 2 wherein the low C2+ gas is natural gas, wellhead gas, coal bed methane (“CBM”), gas obtained from coal gasification, gas obtained from biomass gasification or a combination thereof.

4. The process of claim 1 further comprising: producing synthetic crude from the second product stream.

5. The process of claim 4 further comprising:

producing one or more products selected from the group of lubricant basestock, middle distillate fuels, diesel, lubricants, gasoline, jet fuel, and linear alkylbenzene from the synthetic crude.

6. The process of claim 4 wherein all or a portion of the H₂in the first feed stream is obtained by chemical and/or physical separation of H₂from a portion of the second product stream.

7. The process of claim 4 wherein:

(a) the step of producing the synthetic crude occurs in a Fischer-Tropsch reactor utilizing a Co- or Ru- or Fe-based Fischer-Tropsch catalyst;

(b) the Fischer-Tropsch reactor produces a tail gas; and

(c) all or a portion of the H₂in the first feed stream is obtained by chemical and/or physical separation of H₂from the tail gas.

8. The process of claim 4 wherein the second product stream is produced in a unit that is modular and transportable.

9. The process of claim 1 further comprising:

producing an oxygenate from the second product stream.

10. The process of claim 9 wherein the oxygenate is selected from the group of methanol, ethanol, dimethyl ether and combinations thereof.

11. The process of claim 9 further comprising:

producing one or more products selected from the group of olefins, diesel and gasoline from the oxygenate.

12. The process of claim 9 wherein:

(a) the step of producing the oxygenate occurs in an oxygenate reactor utilizing a Co or Cu-based oxygenate catalyst;

(b) the oxygenate reactor produces a tail gas; and

(c) the tail gas is recycled as all or a portion of the first feed stream.

13. The process of claim 12 wherein 11₂is obtained by chemical and/or physical separation of H₂from the tail gas and added to the first feed stream.

14. The process of claim 1, wherein, in the pre-reforming reactor, the combination of the first feed stream and the second feed stream is conducted using a catalyst comprising an active metal dispersed on a support, where the active metal comprises at least one metal selected from the group consisting of Pt, Rh, Ru, Ni, Co, Pd, Ir and combinations thereof.

15. The process of claim 14, wherein the support is at least one member selected from the group consisting of TiO₂, ZrO₂, alkaline-earth metal hexaaluminates, monoclinic zirconia and alumina.

16. The process of claim 14, wherein the active metal is at least one member selected from the group consisting of Ir, Pt and Pd; and the support comprises at least one member selected from the group consisting of monoclinic zirconia and an alkaline-earth metal hexaaluminate.

17. The process of claim 14, wherein the active metal is at least one member selected from the group consisting of Ir, Pt and Pd, the support comprises at least one member selected from the group consisting of alumina and an alkaline-earth hexaaluminate, and the catalyst further comprises one or more rare earth oxide promoters.

18. The process of claim 1 wherein the first feed stream comprises more than 10% of the hydrocarbons and/or alcohols having two or more carbon atoms.

19. The process of claim 18 wherein the first feed stream comprises more than 20% of the hydrocarbons and/or alcohols having two or more carbon atoms.

20. The process according to claim 1, wherein the first feed stream has a hydrogen stoichiometric ratio (λ) in the range of 0.2 5≦λ≦1.5.

21. The process according to claim 1, wherein the first feed stream has a hydrogen stoichiometric ratio (λ) in the range of 0.25≦λ≦1.

22. The process of claim 1 wherein the syngas generation reactor is selected from the group of steam methane reformers, CO2 dry reformers, autothermal reformers, catalytic partial oxidation reactors and thermal partial oxidation reactors.

23. The process of claim 1 wherein the syngas generation reactor comprises a component selected from the group of ion transport membranes and microchannel reactors.

24. The process of claim 1 wherein the second product stream is produced using air, oxygen-enriched air, or nominally 100% oxygen.

25. The process of claim 1 further comprising:

desulphurizing the first feed stream prior to feeding the first feed stream into the pre-reforming reactor.

26. The process of claim 1 further comprising:

feeding into the syngas generation reactor with the first product stream an additional feed stream comprising one or more members selected from the group consisting of steam, air, non-air oxidants, mixtures of desulphurized gases selected from hydrocarbons, carbon oxides, and inert gases.

27. The process of claim 1, wherein the syngas generation reactor is a, steam methane reformer.

28. The process of claim 1, wherein the catalyst is in a form selected from the group consisting of powders, granulates, tablets, extrudates, and washcoats on ceramic or metallic monoliths, or tubular or plate or corrugated plate structures.

29. The process of claim 1, wherein the first feed stream is introduced into the prereforming reactor prior to the second feed stream being introduced.

30. The process of claim 1, wherein the second feed stream is introduced into the prereforming reactor prior to the first feed stream being introduced.

31. The process of claim 1, wherein the first feed stream and second feed stream are introduced into the pre-reforming reactor simultaneously.

32. The process of claim 1, wherein the first feed stream and second feed stream are combined prior to introduction into the pre-reforming reactor.

33. The process of claim 1 wherein the process is utilized at a production location utilizing a mobile catalyst activation and/or regeneration process.

34. The process of claim 1 wherein the syngas generation unit is modular and transportable.

35. A process comprising:

the first feed stream comprises a mixture of H₂and at least one component selected from the group consisting of hydrocarbons having two or more carbon atoms and alcohols having two or more carbon atoms, wherein more than 20% of the first feed stream comprises said hydrocarbons and/or alcohols having two or more carbon atoms and the amount of hydrogen is such that the first feed stream has a hydrogen stoichiometric ratio (λ) in the range of 0.25≦λ1; and

the second feed stream comprises steam, wherein the molar ratio of steam to carbon atom contained in the combined first and second feed stream, S:C, is in a range from 3:1 to 4:1;

feeding the first product stream into a syngas generation reactor; and

reacting the first product stream in the syngas generation reactor to produce a second product stream comprising synthesis gas,

separating H₂from the second product stream and using the separated H₂to provide at least some of the H₂in the first feed stream.